ALGORITHMS CAN PREDICT' INHIBITORS CAN CONTROL NORM SCALE

John E. Oddo
Water Research Institute Inc.
Houston

Mason B. Tomson
Rice University
Houston

Formation of the most common naturally occurring radioactive material (NORM) containing scale, barium sulfate (BaSO4), can be effectively predicted and controlled based on water chemistry and selecting the most effective scale inhibitors.

Several relatively simple equations can indicate if sulfate scales will form in wells and surface production facilities.

For control of BaSO4 scale, laboratory tests showed phosphinopolycarboxylate to be an effective scale inhibitor under the conditions tested.

NORM SCALE

Some oil field scales have the potential to contain regulated levels of NORM, generally in the form of radium-226. In the U.S., between 300,000 and 1 million tons/years of NORM scale are produced, if all NORM scales are included. However, these estimates drop dramatically to 15,000 50,000 tons/year if scales are limited to greater than 2,000 picocuries/g (pCi/g).1 NORM definitions and units are discussed in the terminology box on the next page.

The uncertainties in the amount of material produced and the low average radionuclide content make it difficult to assess the risk of NORM. However, state agencies have defined and are further defining regulations to monitor and dispose of NORM scale materials and scaled equipment.

In the recovery of gas and oil, mineral scares form deposits in field production facilities because of temperature and pressure changes. Scale deposition in producing wells and associated facilities negatively impacts production rates and is expensive to treat and remediate, regardless of the environmental regulations.

The most common NORM containing scale is BaSO4, or barite.

BASO4 OCCURRENCE

BaSO4 scale occurs during gas and oil production in many places throughout the world. In the U.S., it can be found in such areas as the Michigan basin, along the coast of the Gulf of Mexico, Oklahoma, and Alaska. It is formed because of temperature and pressure changes on the produced water during production, by commingling water from different produced zones in the same well, and by mixing incompatible water.

The low solubility2 5 of BaSO4 is demonstrated by the extreme likelihood that the scale will form when water containing even relatively low concentrations of sulfate is mixed with water containing relatively low concentrations of barium.

As a rule of thumb, BaSO4 is about half as soluble at 77 F. (25 C.) as at 203 F. (95 C.), regardless of salt concentration.6 Furthermore, the solubility is about half as much at atmospheric pressure as at 6,250 psi.4

PREDICTION ALGORITHM

Complex functions and computer codes exist for calculating barite solubilities as a function of temperature, pressure, and ionic strength. However, the authors have generated relatively simple functions for calculating the solubility of barite, as well as the other common sulfate and calcium carbonate scales in petroleum systems.7 The equations for the sulfate scales are shown in the equation box.

A negative saturation index (SI) indicates a nonscaling condition. A zero SI indicates an equilibrium condition, and a positive SI indicates that scale may form in the system.

An example of a typical brine composition from the Ninian field in the North Sea and sea water composition is shown in Table 1. The logarithm of the conditional equilibrium constant for MgSO4 and CaSO4 solution complexes is calculated in the example box.

Using the downhole temperature of 104 C. (220 F.) and a pressure of 26.647 megapascals (4,300 psi), log Kst equals 1.79.

The free [SO42-] and [Ba2+] concentrations are found to be 11.0 mg/l. (0.00011 molar) and 20 mg/l. (0.00015 molar), respectively.

The necessary values have now been determined for substitution to determine the SI index for the Ninian field formation waters at downhole conditions.

The SI of 0.07 is within experimental error of zero, or the equilibrium condition, as would be expected if the reservoir contained solid barite. A similar calculation for the seawater composition in Table 1 determines an SI of 1.45 for barite under the same conditions. However, a 30/50 mixture of the two waters would generate an SI of 1.12 at downhole conditions and serious scaling with barium sulfate is predicted.

Indeed, this is found to be the case in wells, and scale treatment programs have been initiated to combat the problem.8

MICHIGAN BASIN STUDY

BaSO4 scale containing NORM as well as calcium carbonate scale occurs in gas production facilities in the Antrim formation in northern Michigan.

In addition, the operators reported very high sulfate concentrations in some wells, in excess of 4,000 mg/l. sulfate, while in most other wells the sulfate amount was low or undetectable. For a complete discussion see Reference 9.

The scale study of this area systematically characterized BaSO4 scale, both as to occurrence and environmental hazard, and also evaluated scale control methods using typical brines from the area. Water samples were collected from 133 locations and from 108 wells. Some wells were sampled more than once and the remaining locations were surface facilities and disposal wells.

Total dissolved solids in these wells ranged from 25,000 to over 180,000 mg/l. Barium concentrations ranged from less than 1 mg/l. to 185 mg/l. with an average of 43 mg/l.

Where sulfate was detected, sulfate concentrations were measured between less than 3 mg/l. (the detection limit) and 3,233 mg/l., with an average of 284 mg/l. However, these average values can be misleading because when sulfate was detected, the barium concentration was generally quite low and vica versa.

Radiation levels at the facilities varied from background (about 5 u rems/hr) to over 3,200 u rems/hr.

Water samples were taken from selected wells and surface facilities in Michigan to cain insight into the scaling based on the water chemistries. SI calculations indicated that both CaCO3 and BaSO4 would be expected to form in the producing facilities and both scales were identified in the field.

NORM scale formed because of commingling waters in the surface facilities from different wells. Some waters were high in sulfate, 20 3,233 mg/l., while others were relatively high in barium, 10 185 mg/l.

In addition, a second type of scale BaSO4 formed in at least 12 wells without commingling. This scale formed as a function of the temperature and pressure changes associated with production. The data indicated that the waters obtained from all of the wells are in equilibrium with BaSO4 in the reservoir.

SCALE TREATMENT

Production facilities can be treated for scale formation by two different procedures.10 11 The first is to inject the chemical directly into the produced water stream with a pump and associated tubing. The second is to inject chemical into the producing formation and fix the material in the reservoir through precipitation and/or adsorption.

With this method, inhibitor is then released into the brine stream at a concentration desirable for scale inhibition. This is known as a "squeeze" treatment. It was recommended that the scale be treated by the injection of chemical threshold scale inhibitor into the surface equipment, where commingling of waters was the problem.

Wells that scaled during production required inhibitor squeeze procedures. Ten inhibitor squeezes were completed in late 1992.

These wells continue to be protected from NORM scale formation as of this writing.

TESTING INHIBITORS

Although chemical threshold scale inhibitors have been used all over the world to control unwanted deposits,12 there is little agreement on which inhibitor should be used for different sets of conditions. In addition, no systematic methods to apply inhibitors have been outlined.

In Michigan, the wells needed to be treated for both CaCO3 and BaSO4 scale. This required a scale inhibitor(s) to inhibit both types of scale effectively.

Inhibitor Evaluations were undertaken in the laboratory to determine the most effective chemical scale inhibitor(s).

A dynamic flow through apparatus (Fig. 1) duplicated the production system in the laboratory. The apparatus is capable of temperatures from 0 F. ( 18C.) to 302 F. (150 C.), pressures from atmospheric to 4,500 psi and flow rates comparable to producing wells.

This apparatus made it possible to evaluate scale inhibitors under realistic conditions and reduced from days to hours the time needed to test new chemical inhibitors over a range of concentrations.13 14

Inhibitors for calcium carbonate, iron(II) carbonate, calcium sulfate, strontium sulfate, barium sulfate, and other scales can be evaluated. Dynamic testing results in an effectiveness ranking of the inhibitors by the minimum effective dose for each inhibitor.

This is contrasted with static bottle tests, where inhibitors are all treated the same and ranked according to their percent effectiveness. To be effective in the field, an inhibitor must be 100% effective at all times or scale will form. Even periodic scale can be devastating to an operation over a period of months or years.

The test apparatus can be computer controlled with information from the tests feeding back to the computer. Because the components of the mixing pumps and the entire system that Contact the brines are totally metal free, essentially there is no adsorption of inhibitor onto the pump components or tubing.

The tubing materials used in the evaluations are Teflon or PEEK (polyether-etherketone) depending on pressure requirements.

It is important to recognize that inhibitor adsorption can cause "memory effects," i.e., inhibitor adsorbed from previous experiments can be slowly released and interfere with later evaluations. The elimination of this variable is important for accurate and reproducible results in minimum time.

Where scale inhibitors have been evaluated for a specific field, results obtained using the flow through apparatus have been shown to agree with field testing.

Eight generic scale inhibitors were evaluated for possible use in the Michigan area. The composition of the brine used in the laboratory evaluations is shown in Table 2. The inhibitors evaluated are listed in Table 3.

The most effective scale inhibitor tested for BaSO4 scale was phosphinopolycarboxylate (PPPC). This material has been found to be effective in other areas for BaSO4 scale inhibition. In other studies, however, PPPC has proven less effective than phosphonates or phosphate esters with respect to CaCO3 scale.

Because PPPC is more effective against BaSO4 scale formation, it was recommended that the Michigan wells be squeezed with a 50/50 combination of a phosphonate (aminotrimethylene phosphonic acid) and the PPPC inhibitor.

ACKNOWLEDGMENTS

This work was supported by the Gas Research Institute, but in no way does this constitute an endorsement by GRI of any products or views contained herein. In addition, the inhibitor evaluations do not constitute a comprehensive study of inhibitors, nor are any product claims made for any application. The authors wish to thank Ward Lake Energy, Great Lakes Carbon, Muskegon Development, Terra Energy, and Star Inc. for their assistance in this study. In addition, the work is supported by consortium of companies including Texaco Inc., Conoco Inc., Champion Technologies, FMC Corp., and Zapata Corp.

REFERENCES

Spaite, P.W. and Smithson, G.R., "Technical and Regulatory Issues Associated with Naturally Occurring Radioactive Material (NORM) in the Gas and Oil Industry," Gas Research Institute, Final Report, GRI 92/0178, 1992.
Schulien, S., "High Temperature/High Pressure Solubility Measurements in the Systems BaSO4 NaCl H20 and SrSO4-NaCl H20 in Connection with Scale Studies," SPE Paper No. 16264, International Symposium on Oilfield Chemicals, San Antonio, 1987, pp. 233 42.
Templeton, C.C., "Solubility of Barium Sulfate in Sodium Chloride Solutions from 25 C. to 95 C.," Journal of Chem. and Eng. Data, October 1960, pp. 514 16.
Oddo, J.E., and Tomson, M.B., "Why Scale Forms in the Oil Field and Methods to Predict It," SPE Paper No. 21710, Production Operations Symposium, Oklahoma City, 1991.
Blount, C.W., "Barite Solubilities and Thermodynamic Quantities up to 300 C. and 1400 Bars," American Mining, Vol. 62, 1977, pp. 942 57.
Patton, C.C., Applied Water Technology, Campbell Petroleum Series, Norman, Okla., 1986.
Oddo, J.E., and Tomson, M.B., "Improvements on the Oddo-Tomson Saturation Indices for Common Oil Field Scales," SPE Paper No. 21710, SPE Production and Facilities, in press, 1993.
Shuler, P.J., and Jenkins, W.H., "Prevention of Downhole Scale Deposition in the Ninian Field," SPE Paper No. 19263/1, Offshore Europe 89, Aberdeen, 1989.
Oddo, J.E., et al., "The Chemistry, Prediction and Treatment of Scale Containing NORMs in Antrim Gas Fields," Production Operations Symposium, Oklahoma City, 1493.
Kan, A.T.. et al., "Sorption and Fate of Phosphonate Scale Inhibitors in the Sandstone Reservoir: Studied via Laboratory Apparatus with Core Material," SPE Paper No. 21714, Production Operations Symposium, Oklahoma City, 1991.
Oddo, J.E., and Tomson, M.B., "Scale Control, Prediction and Treatment or How Companies Evaluate a Scaling Problem and What They Do Wrong," Paper No. 32, NACE Corrosion 92, Nashville, 1992, pp. 34/1 34/12.
Cowan, J.C., and Weintritt, D.J., Water Formed Scale Deposits, Gulf Publishing Co., Houston, 1976.
Oddo, J.E., et al., "Brine Chemistry and Control of Adverse Chemical Reactions with Natural Gas Production," Gas Research Institute, Annual Report, 1991.
Oddo, J.E., Sloan, K.M., and Tomson, M.B., "Inhibition of CaCO3 Precipitation at High Temperatures and Pressures in Brine Solutions: A New Flow System for High Temperature and Pressure Studies," JPT, Vol. 34, 1982, pp. 2409 11.
Matty, J., and Tomson, M.B., "Effect of Multiple Precipitation Inhibitors on Calcium Carbonate Nucleation," Applied Geochemistry, Vol. 3, 1988, pp. 549 56.

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